Calibration of a well acoustic sensing system

ABSTRACT

A method of calibrating a distributed acoustic sensing system can include receiving predetermined acoustic signals along acoustic sensors distributed proximate a well, and calibrating the system based on the received acoustic signals. A method of calibrating an optical distributed acoustic sensing system can include displacing an acoustic source along an optical waveguide positioned proximate a well, transmitting predetermined acoustic signals from the acoustic source, receiving the acoustic signals with the waveguide, and calibrating the system based on the received acoustic signals. A well system can include a distributed acoustic sensing system including an optical waveguide installed in a well, and a backscattered light detection and analysis device, and at least one acoustic source which transmits predetermined acoustic signals at spaced apart locations along the waveguide. The device compensates an output of the system based on the acoustic signals as received at the locations along the waveguide.

BACKGROUND

This disclosure relates generally to equipment utilized and operationsperformed in conjunction with a subterranean well and, in examplesdescribed below, more particularly provides for calibration of a wellacoustic sensing system.

An optical distributed acoustic sensor (DAS) system uses an opticalwaveguide, such as an optical fiber, as a distributed sensor to detectacoustic waves that vibrate the waveguide. This sensing is performed bydetecting backscattered light transmitted through the waveguide. Changesin the backscattered light can indicate not only the presence ofacoustic waves, but also certain characteristics of the acoustic waves.

Unfortunately, when an optical waveguide is installed in a well, variousfactors (such as, acoustic couplings and wellbore construction) caninfluence measured acoustic power as a function of frequency, as well asother characteristics of the acoustic waves which impinge on the opticalwaveguide. For example, if the waveguide is positioned outside of casingin a wellbore, the intensity of acoustic waves originating in the casingand impinging on the waveguide outside of the casing can varysignificantly along the waveguide, depending on changes in the casingthickness, changes in cement outside the casing, etc. Additionally, thisvariation in the characteristics of the acoustic waves which impinge onthe waveguide makes it difficult to interpret measurements made by a DASsystem.

Thus, it will be appreciated that improvements are continually needed inthe art of using distributed acoustic sensing systems in conjunctionwith subterranean wells. Such improvements could be useful forcalibrating well acoustic sensing systems other than DAS systems, forexample, well acoustic sensing systems which include arrays ofmultiplexed point sensors, such as fiber Bragg gratings, or non-opticaldistributed acoustic sensing systems.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a representative partially cross-sectional view of a wellsystem and associated method which can embody principles of thisdisclosure.

FIG. 2 is a representative partially cross-sectional view of anotherexample of the well system and method.

FIG. 3 is a representative plot of measured acoustic intensity data as afunction of well depth and time, and indicates abrupt changes inintensity where well features change abruptly.

FIG. 4 is a representative schematic view of an interrogator having apolarization controller used for fading mitigation.

FIG. 5 is a representative flowchart for a method of mitigating fadingusing the polarization controller.

FIG. 6 is a representative partially cross-sectional view of anotherexample of the system and method, in which a seismic source at a surfacelocation and a three-axis geophone are used for calibration.

FIG. 7 is a representative partially cross-sectional view of anotherexample of the system and method, in which an acoustic source in anoffset well and a three-axis geophone are used for calibration.

DETAILED DESCRIPTION

Representatively illustrated in FIG. 1 is a system 10 for use with awell, and an associated method, which system and method can embodyprinciples of this disclosure.

However, it should be clearly understood that the system 10 and methodare merely one example of an application of the principles of thisdisclosure in practice, and a wide variety of other examples arepossible. Therefore, the scope of this disclosure is not limited at allto the details of the system 10 and method described herein and/ordepicted in the drawings.

In this example, an active sound source or sources are housed within anobject (a ball, a cylinder, etc.), which is dropped, injected or loweredby cable into a wellbore for the purpose of calibrating an opticaldistributed acoustic sensor previously installed in a well. In the caseof dropping or injecting one or more objects with active soundsource(s), the object(s) may also be used to control downhole devices(such as valves, etc.) and/or to plug perforations.

There are various vibration speakers, vibrating actuators, and acoustictransducers, e.g., flextensional SONAR transducers, etc., that arecapable of actively producing sounds within an object. Such acousticsources are well known to those skilled in the art and, thus, are notdescribed further here.

In one example, the distributed acoustic sensor calibration uses ameasurement of a power of acoustic signals at several acousticfrequencies, as well as an extent of the acoustic signals. Thecalibration will ideally be done over the entirety of the acousticsensor, or at least in a specific wellbore area of interest. Ameasurement of the intensity of the sound energy provides the acousticsensitivity as a function of position along the distributed acousticsensor. A measurement of the extent of the acoustic signal along theacoustic sensor provides a well location dependent point spread function(e.g., blurring function, blurring kernel, etc.) of acoustic waves asdetected by the sensor.

Spatial blurring can result from an acoustic sensor at a particularlocation picking up acoustic waves which originate at multiplelocations. That is, a measurement of acoustic power at a specific pointin a well is comprised of sounds far away from this specific location. Acalibration method to account for this effect is proposed here. Acalibration measurement of the acoustic point spread function (spatialblurring function, impulse response, etc.) would allow the acousticsignals to be spatially deconvolved, inverted, deblurred, etc., toenhance the sounds heard at only one location in the well. Yet anothercalibration factor for distributed acoustic sensing can be determinedfrom measuring an echo-response (i.e., an acoustic impulse response) ofthe well, so that echoes in the well can be removed or reduced asdesired. This is typically done using a frequency domain adaptive filterthat maximizes a term referred to as the Echo Return Loss Enhancementfactor, which is a measure of the amount the echo has been reduced orattenuated.

The sounds can be emitted as continuous single-frequency tones,continuous dual tone multiple frequency (DTMF, similar to what is usedfor pushbutton telephones), continuous multiple-frequency tones,continuous wide spectrum tones, continuous white noise, continuouscolored noise, continuously repeating swept-frequency waveforms,continuous pseudorandom waveforms, or other continuously repeatingcomplex waveforms. The sounds can also be emitted as pulsedsingle-frequency tones, pulsed dual tone multiple frequency (DTMF,similar to what is used for pushbutton telephones), pulsedmultiple-frequency tones, pulsed wide spectrum tones pulsed white noise,pulsed colored noise, pulsed swept-frequency waveforms, pulsedpseudorandom waveforms, or other pulsed complex waveforms.

The sounds can be transmitted in synchrony. The sounds can betransmitted at different volumes at each location. The scope of thisdisclosure is not limited to any particular predetermined acousticsignals transmitted by an acoustic source.

If the sounds are transmitted at different volumes at various locations,nonlinearities in the gain response as a function of location in thewell can be determined.

The FIG. 1 example provides for in-situ calibration of an opticalacoustic sensor used to measure acoustic energy. The sensor comprises adistributed acoustic sensing (DAS) system, which is capable of detectingacoustic energy as distributed along an optical waveguide. The sensorcomprises surface electronics and software, commonly known to thoseskilled in the art as an interrogator, and the optical waveguide. Theoptical waveguide may be installed in a wellbore, inside or outside ofcasing or other tubulars, optionally in cement surrounding a casing,etc.

The interrogator launches light into the optical waveguide (e.g., froman infrared laser), and the DAS system uses measurement of backscatteredlight (e.g., coherent Rayleigh backscattering) to detect the acousticenergy along the waveguide. Signal processing is used to segregate thewaveguide into an array of individual “microphones” or acoustic sensors,typically corresponding to 1-10 meter segments of the waveguide.

The waveguide may be housed in a metal tubing or control line andpositioned in a wellbore. In some examples, the waveguide may be incement surrounding a casing, in a wall of the casing or other tubular,suspended in the wellbore, in or attached to a tubular, etc. The scopeof this disclosure is not limited to any particular placement of thewaveguide.

A sensitivity of the waveguide to acoustic energy can dependsignificantly on how the waveguide is installed in the well, and onlocal variations (such as, cement variations, casing variations,presence of other equipment such as packers or cable clamps, temperaturevariations, presence of gas or liquids in the wellbore, type of fluid inthe wellbore or cement, etc.). For example, significant temperaturevariations along a wellbore can affect the amount of Rayleighbackscattering in the waveguide.

In a calibration procedure described below, these variations can becompensated for by detecting predetermined acoustic signals transmittedalong the waveguide by an acoustic source. The acoustic source maycomprise an object which is released, injected or lowered into thewellbore using an electric wireline, a slickline, a wellbore tractor,etc.

By emitting sound in a controlled manner from the acoustic source, andreceiving the resulting acoustic energy along the waveguide, the DASsensor can measure the acoustic sensitivity (e.g., the acoustic couplingfactor or gain factor) as a function of acoustic frequency, and as afunction of position along the waveguide. Another embodiment is tomeasure the cumulative power only as a function of position along thewaveguide.

The measurement of the gain per DAS channel allows for a gainnormalization scale factor to be applied at each location. This gainscale factor can be either frequency dependent or not.

Another embodiment is to synchronize the sound emissions with a clock soa phase of the signals can be measured as a function of position alongthe waveguide. The calibrating technique can include measuring the phaseof the acoustic signal along the optical waveguide. Measured phase orphase inversion is related to either stretching or compression of theoptical waveguide.

To measure the phase, the acoustic source is synchronized with the clockof the interrogator. The acoustic source preferably has an accurateclock to make this measurement.

The sound emitted from the acoustic source can also travel along thewellbore and acoustically illuminate other sections of the waveguide,thus allowing determination of the point spread function as a functionof acoustic frequency and as a function of position along the wellbore.These parameters (acoustic sensitivity and point spread function) areused to calibrate the DAS system.

The measurement of the acoustic point spread function allows theacoustic field to be deblurred using any of a number of deblurringmethodologies, such as, the Wiener deblurring filter, regularizeddeblurring filter, Lucy-Richardson deblurring algorithm, blinddeconvolution deblurring algorithm, or Vardi-Lee expectationmaximization deblurring algorithm, for example.

Generally, there are a percentage (usually small) of channels of someDAS systems that experience an issue known as “fading,” where thesignal-to-noise ratio (SNR) of the channel will be reduced temporarily.This reduction in SNR, may reduce the accuracy of the calibration.Fading can be caused by several different effects, with polarizationeffects being a predominant cause.

The calibration can be done by averaging out the occasional fadingeffects by collecting sufficient data over a longer time. Additionally,by oversampling spatially, the calibration data for faded channels maybe ignored and the calibration of adjacent non-faded channels usedinstead for those that are faded.

In an additional method representatively illustrated in FIGS. 4 & 5, apolarization controller 48 is placed in series with an optical source 50of the device 26 to adjust the polarization of the light being launchedinto the optical waveguide 22. Backscattered light is detected by anoptical receiver 52.

By adjusting the polarization of the outgoing light, the relativebackscattered optical power from each channel will change. Using aniterative optimization process of adjusting the launch polarization (seeFIG. 5), the optical signal power from the channel being currentlycalibrated is optimized until an acceptable signal to noise ratio forthe channel being calibrated is obtained. Use of polarizationmaintaining fiber optic cables can also be employed to mitigatepolarization fading, etc.

In one example, the object which emits the acoustic signals can beinjected into the wellbore during a fracturing or other stimulationoperation. The object could, for example, be a ball, dart or plug usedto actuate one or more valves for selectively communicating between thewellbore and an earth formation penetrated by the wellbore. In thismanner, the calibration procedure can be part of the stimulationoperation, instead of separate therefrom.

In another example, the object can be lowered into the wellbore using awireline, slickline or wellbore tractor. This procedure could beperformed separately as needed, or as part of another operation (suchas, a wireline logging operation).

FIG. 1 depicts an example in which an acoustic source 12 is conveyedinto a wellbore 14 by means of a cable 16 (e.g., wireline, slickline,other type of cable, etc.). The wellbore 14 in this example is linedwith casing 18 and cement 20, but in other examples the wellbore couldbe uncased or open hole.

As used herein, the term “casing” is used to indicate a protectivewellbore lining. Casing may be made up of tubulars known to thoseskilled in the art as casing, liner or tubing. Casing may be segmentedor continuous. Casing may be made of metals, composites or othermaterials.

In the FIG. 1 example, an optical waveguide 22 is positioned external tothe casing 18, and in the cement 20. The waveguide 22 may be attachedexternally to the casing 18. In other examples, the waveguide 22 couldbe positioned in a wall of the casing 18, in an interior of the casing,or in any other location.

Note that one section of the casing 18 has a greater thickness thanadjacent sections. This can cause acoustic signals transmitted throughthe casing 18 to be more attenuated at the thicker section, so that thewaveguide 22 detects a lower intensity of the acoustic signals at thatlocation.

It would be desirable to calibrate an output of a DAS system 24(including the waveguide 22 and an interrogator or backscattered lightdetection and analysis device 26), so that the output is compensated forsuch variations. Of course, other types of variations (e.g., variationsin fluid types in the wellbore 14, casing 18 and cement 20, variationsin temperature, etc.) can also be compensated for in the calibrationprocedure. The scope of this disclosure is not limited to compensationfor any particular type of variation.

In the calibration procedure, the acoustic source 12 is displaced tovarious different locations along the waveguide 22, and the acousticsource transmits a predetermined acoustic signal 28 at the differentlocations. The acoustic source 12 may transmit the acoustic signalcontinuously while the source is being displaced along the waveguide 22,or the acoustic signal could be separately transmitted at the respectiveseparate locations.

As mentioned above, the acoustic signal 28 may comprise a single ormultiple acoustic frequencies, certain combinations of frequencies,white noise, colored noise, or pseudorandom waveforms. The acousticsignal 28 may be transmitted at a single or multiple power levels. Thescope of this disclosure is not limited to any particular type ofacoustic signal(s) 28 transmitted by the acoustic source 12.

Referring additionally now to FIG. 2, another example of the system 10is representatively illustrated. In this example, the acoustic source 12is dropped or injected into the well, such as, during a fracturing orother stimulation operation.

The acoustic source 12 emits the acoustic signal 28 as it displacesthrough a tubular string 30 in the wellbore 14. A valve 32 is includedin the tubular string 30 for providing selective communication betweenan interior of the tubular string 30 and an earth formation 34penetrated by the wellbore 14. The acoustic source 12 may comprise aball, plug or dart which, when received in the valve 32, allows thevalve to be operated to permit or prevent such communication.

Thus, in the FIG. 2 example, the acoustic source 12 serves at least twopurposes: enabling calibration of the DAS system 24, and enablingoperation of the valve 32. In this manner, the DAS system 24 can becalibrated while the stimulation operation proceeds. In other examples,the acoustic source 12 could be used to plug perforations 36, or toperform any other function.

Although only one acoustic source 12 is depicted in each of the FIGS. 1& 2 examples, it will be appreciated that any number of acoustic sourcesmay be used. Multiple acoustic sources 12 could be displaced along thewaveguide 22 simultaneously or separately. The acoustic sources 12 couldeach transmit the same predetermined acoustic signal 28, or differentacoustic signals could be transmitted by respective different acousticsources.

Referring additionally now to FIG. 3, an example plot of measuredacoustic intensity data as a function of well depth and time isrepresentatively illustrated. Note that, in the plot abrupt changes inintensity are indicated, for example, where well features changeabruptly.

The presence of the thicker casing 18, a packer, or otherdiscontinuities can be causes of the abrupt changes in intensity. Use ofthe calibration techniques described above in conjunction with theacoustic source 12 can eliminate or at least significantly reduce theabrupt changes in acoustic intensity as depicted in the FIG. 3 plot.

Although the examples described herein use the waveguide 22 as adistributed acoustic sensor, multiple individual acoustic sensors mayalternatively (or additionally) be used. For example, multiplemultiplexed fiber Bragg gratings could be used as discreet acousticsensors 40 (see FIG. 1) distributed along the waveguide 22.

The calibration techniques described herein may be used to calibrate themeasurements made using the distributed acoustic sensors 40. Thecalibration techniques described herein may also be used to calibratemeasurements made using the distributed acoustic sensors 40, even if thesensors are not optical sensors.

One of the issues with conventional DAS systems is that a fiber channelis a sensor that produces a single “value,” but the sensor actuallyresponds to energy propagating in different orientations or directionssimultaneously. In some examples described below, a three-component (x,y, z) geophone can be used as a reference in a calibration technique, sothat vibration energy in the x, y, and z directions can be separated outto determine what the fiber's response is to vibrations that areoriented in the x, y, and z axis directions separately. The x, y, and zdirections can be any three orthogonal directions as long as theorientation is known during calibration.

For example, in many seismic applications, it would be desirable to knowhow the fiber responds to p-waves coming from the side (cross-well)versus longitudinal (along the wellbore). For microseismic detection, itwould be desirable to know the response of the fiber to shear ors-waves, including s-waves of different polarizations, because shearwaves are a major energy component of microseismic events (typicallyfractures). If the response of the fiber to horizontally polarizeds-waves and vertically polarized s-waves could be separately determined,it would be possible to infer the response to other polarizations. Ifthe calibration could help in determining the polarization of the shearwave components generated by a microseismic event, the orientation(azimuth) of the fracture (which is a very important piece ofinformation) could be determined.

Due to the distance and weakness of most microseismic events, it wouldbe desirable to combine the response of many DAS channels usingtechniques like beamforming in order to see these events. To dobeamforming effectively, each channel is preferably corrected ornormalized based on a calibration.

Stoneley waves (or tube waves) travel along the walls of the boreholeand are a noise source in vertical seismic profiling. Preferably, theeffect of Stoneley waves is subtracted out of a recorded signal beforestacking when doing a vertical seismic profiling application. IfStoneley waves could be generated at a wellhead or using a downholesource designed to generate that kind of wave, we could see how eachchannel responds and this will enable us able to compensate for them invertical seismic profiling or other applications.

As representatively illustrated in FIG. 6, another calibration methodcan include the use of a remote vibratory or impulse seismic source 12,and preferably, a calibrated reference receiver 42 (such as a three-axisgeophone) placed adjacent to the distributed acoustic sensor (such asthe optical waveguide 22 or sensors 40). The calibrated referencereceiver 42 is not required for the methods described herein, but willimprove the accuracy of the calibration by accounting for the signalattenuation and distortion effects caused by the formation 34 betweenthe source 12 and the DAS sensor. In this method, the seismic source canbe located either on the surface (as depicted in FIG. 6), or in a nearbywell (as depicted in FIG. 7). A calibrated seismic receiver 42(accelerometer, geophone, hydrophone, etc.), for example a three-axisgeophone, is optionally lowered into the well containing the distributedacoustic sensor to the depth of the channel being calibrated. Theseismic source, located at the surface or a nearby well is energized toemit seismic energy (P-wave, S-wave, etc.) to be received by the DASsensor. Both the DAS sensor and geophone receive substantially the sameenergy. Using the receiver 42 as a reference, the DAS sensor response toa variety of different signals produced by the seismic source 12,including various amplitude, frequency, and directional variations, canbe compared to the receiver response to derive a calibration for the DASsensor.

For example, in one method the seismic source 12 is placed near awellhead 44, such that a seismic wave is sent vertically down the lengthof the well and longitudinally along the length of the DAS sensor. Inanother method, the seismic source is located a significant distanceaway from the wellhead 44 so that the seismic energy is oriented mostlyhorizontally. In a deviated or horizontal well, the direction of travelof the seismic energy relative to the wellbore 14 would be altered orreversed based on the layout of the wellbore.

In the case of a cross-well calibration (as depicted in FIG. 7), theseismic source 12 is lowered into a neighboring well 46. The seismicsource may generate S-waves or P-waves to provide a multicomponentcalibration of the DAS cable (e.g., optical waveguide 22) based on thetype of wave. The cross-well calibration case may be particularlyimportant for micro-seismic detection during hydraulic fracturingoperations where the DAS cable may be located in an observation wellnearby the well to receive the fracturing treatment. In this scenario,the seismic source is lowered into the well to be fractured to emitseismic energy (P-wave, S-wave, etc.) into the formation. The DAS cablereceives the seismic energy in the observation well, along with acalibration geophone to provide the calibration data.

It may now be fully appreciated that the above disclosure providessignificant advancements to the art of optical distributed acousticsensing. In examples described above, variations in acoustic sensitivityof the DAS system 24 can be compensated for by displacing the acousticsource 12 along the optical waveguide 22 or other distributed acousticsensors 40, with the acoustic source transmitting the predeterminedacoustic signal 28 at different locations along the sensors. In thismanner, the output of the DAS system 24 is calibrated.

A method of calibrating an optical distributed acoustic sensing system24 is described above. In one example, the method comprises receivingpredetermined acoustic signals 28 along an optical waveguide 22 or otherdistributed acoustic sensors 40 positioned proximate a well, andcalibrating the optical distributed acoustic sensing system 24 based onthe received predetermined acoustic signals 28.

The method can include displacing at least one acoustic source 12adjacent the optical waveguide 22. The displacing can include displacingthe acoustic source 12 through a wellbore 14.

The acoustic source 12 preferably transmits the predetermined acousticsignals 28 at multiple locations along the optical waveguide 22.

The receiving step can include determining a power, power spectraldensity, phase, and/or extent of the acoustic signals 28 as receivedalong the optical waveguide 22.

The calibrating step can include measuring an acoustic sensitivity alongthe optical waveguide 22.

In one example, a method of calibrating an optical distributed acousticsensing system 24 can include displacing at least one acoustic source 12along an optical waveguide 22 positioned proximate a well, transmittingpredetermined acoustic signals 28 from the acoustic source 12, receivingthe predetermined acoustic signals 28 with the optical waveguide 22, andcalibrating the optical distributed acoustic sensing system 24 based onthe received predetermined acoustic signals 28.

A well system 10 is also described above. In one example, the wellsystem 10 can comprise an optical distributed acoustic sensing system 24including an optical waveguide 22 installed in a well and abackscattered light detection and analysis device 26, and at least oneacoustic source 12 which transmits predetermined acoustic signals 28 atmultiple spaced apart locations along the optical waveguide 22.

In this example, the backscattered light detection and analysis device26 compensates an output of the optical distributed acoustic sensingsystem 24 based on the predetermined acoustic signals 28 as received atthe spaced apart locations along the optical waveguide 22. Thebackscattered light detection and analysis device 26 may determine anacoustic sensitivity along the optical waveguide, measure a phase of theacoustic signals along the optical waveguide 22, determine a powerspectral density of the acoustic signals as received along the opticalwaveguide 22, and/or determine an extent of the acoustic signals asreceived along the optical waveguide 22.

In a broad aspect, it is not necessary for the distributed acousticsensing system to be “optical,” or for the distributed acoustic sensorsto be “optical.” A method of calibrating a distributed acoustic sensingsystem 10 can include receiving predetermined acoustic signals 28 alongmultiple acoustic sensors 40 (whether or not the sensors are opticalsensors, and whether or not the sensors comprise channels of an opticalwaveguide, such as an optical fiber) distributed proximate a well; andcalibrating the optical distributed acoustic sensing system 10 based onthe received predetermined acoustic signals 28.

The method can include displacing at least one acoustic source 12adjacent the acoustic sensors 40. The displacing may include displacingthe acoustic source 12 through a wellbore 14.

The acoustic source 12 may transmit the predetermined acoustic signals28 at multiple locations along the acoustic sensors. The acoustic source12 may transmit the predetermined acoustic signals 28 at differentamplitudes at each of the multiple locations.

The acoustic source 12 may transmit the predetermined acoustic signals28 in synchrony with an interrogator (such as the device 26). Thecalibrating step can include measuring a phase of the acoustic signals28 along the acoustic sensors 40.

The receiving step may include determining a power, a power spectraldensity, and/or an extent of the acoustic signals 28 as received alongthe acoustic sensors 40.

The calibrating step can include measuring an acoustic sensitivity alongthe acoustic sensors 40.

The method can include transmitting the acoustic signals 28 from anotherwell 46, or from at or near the earth's surface.

The method can include transmitting Stoneley waves from at or near awellhead 44, or from a downhole location.

The receiving step can include receiving the acoustic signals 28 by athree-axis reference sensor (such as receiver 42) positioned proximatethe distributed acoustic sensors 40 or optical waveguide 22.

The calibrating step can include calibrating the distributed acousticsensing system 24 based on the predetermined acoustic signals 28 asdetected by the three-axis reference sensor 42. The three-axis referencesensor may comprise a geophone.

The calibrating step can include computing an acoustic point spreadfunction along the sensors 40 for each of multiple source 12 locations.The calibrating can further comprise using the point spread functiondetermined by the computing to deblur acoustic emissions along awellbore 14 as received by the distributed acoustic sensors 40.

Although various examples have been described above, with each examplehaving certain features, it should be understood that it is notnecessary for a particular feature of one example to be used exclusivelywith that example. Instead, any of the features described above and/ordepicted in the drawings can be combined with any of the examples, inaddition to or in substitution for any of the other features of thoseexamples. One example's features are not mutually exclusive to anotherexample's features. Instead, the scope of this disclosure encompassesany combination of any of the features.

Although each example described above includes a certain combination offeatures, it should be understood that it is not necessary for allfeatures of an example to be used. Instead, any of the featuresdescribed above can be used, without any other particular feature orfeatures also being used.

It should be understood that the various embodiments described hereinmay be utilized in various orientations, such as inclined, inverted,horizontal, vertical, etc., and in various configurations, withoutdeparting from the principles of this disclosure. The embodiments aredescribed merely as examples of useful applications of the principles ofthe disclosure, which is not limited to any specific details of theseembodiments.

In the above description of the representative examples, directionalterms (such as “above,” “below,” “upper,” “lower,” etc.) are used forconvenience in referring to the accompanying drawings. However, itshould be clearly understood that the scope of this disclosure is notlimited to any particular directions described herein.

The terms “including,” “includes,” “comprising,” “comprises,” andsimilar terms are used in a non-limiting sense in this specification.For example, if a system, method, apparatus, device, etc., is describedas “including” a certain feature or element, the system, method,apparatus, device, etc., can include that feature or element, and canalso include other features or elements. Similarly, the term “comprises”is considered to mean “comprises, but is not limited to.”

Of course, a person skilled in the art would, upon a carefulconsideration of the above description of representative embodiments ofthe disclosure, readily appreciate that many modifications, additions,substitutions, deletions, and other changes may be made to the specificembodiments, and such changes are contemplated by the principles of thisdisclosure. For example, structures disclosed as being separately formedcan, in other examples, be integrally formed and vice versa.Accordingly, the foregoing detailed description is to be clearlyunderstood as being given by way of illustration and example only, thespirit and scope of the invention being limited solely by the appendedclaims and their equivalents.

1. A method of calibrating a distributed acoustic sensing system, themethod comprising: receiving predetermined acoustic signals alongmultiple acoustic sensors distributed proximate a well; and calibratingthe distributed acoustic sensing system based on the receivedpredetermined acoustic signals.
 2. The method of claim 1, furthercomprising displacing at least one acoustic source adjacent the acousticsensors.
 3. The method of claim 2, wherein the displacing furthercomprises displacing the acoustic source through a wellbore.
 4. Themethod of claim 2, wherein the acoustic source transmits thepredetermined acoustic signals at multiple locations along the acousticsensors.
 5. The method of claim 4, wherein the acoustic source transmitsthe predetermined acoustic signals at different amplitudes at each ofthe multiple locations.
 6. The method of claim 4, wherein the acousticsource transmits the predetermined acoustic signals in synchrony with aninterrogator.
 7. The method of claim 6, wherein the calibrating furthercomprises measuring a phase of the acoustic signal along the acousticsensors.
 8. The method of claim 1, wherein the receiving furthercomprises determining a power of the acoustic signals as received alongthe acoustic sensors.
 9. The method of claim 1, wherein the receivingfurther comprises determining a power spectral density of the acousticsignals as received along the acoustic sensors.
 10. The method of claim1, wherein the receiving further comprises determining an extent of theacoustic signals as received along the acoustic sensors.
 11. The methodof claim 1, wherein the calibrating further comprises measuring anacoustic sensitivity along the acoustic sensors.
 12. The method of claim1, further comprising transmitting the acoustic signals from anotherwell.
 13. The method of claim 1, further comprising transmitting theacoustic signals from at or near the earth's surface.
 14. The method ofclaim 1, further comprising transmitting Stoneley waves from at or neara wellhead.
 15. The method of claim 1, further comprising transmittingStoneley waves from a downhole location.
 16. The method of claim 1,wherein the receiving further comprises receiving the acoustic signalsby a three-axis reference sensor positioned proximate the distributedacoustic sensors.
 17. The method of claim 16, wherein the calibratingfurther comprises calibrating the distributed acoustic sensing systembased on the predetermined acoustic signals as detected by thethree-axis reference sensor.
 18. The method of claim 16, wherein thethree-axis reference sensor comprises a geophone.
 19. The method ofclaim 1, wherein the calibrating further comprises computing an acousticpoint spread function along the sensors for each of multiple sourcelocations.
 20. The method of claim 19, wherein the calibrating furthercomprises using the point spread function determined by the computing todeblur acoustic emissions along a wellbore as received by thedistributed acoustic sensors.
 21. A method of calibrating an opticaldistributed acoustic sensing system, the method comprising: receivingpredetermined acoustic signals along an optical waveguide positionedproximate a well; and calibrating the optical distributed acousticsensing system based on the received predetermined acoustic signals. 22.The method of claim 21, further comprising displacing at least oneacoustic source adjacent the optical waveguide.
 23. The method of claim22, wherein the displacing further comprises displacing the acousticsource through a wellbore.
 24. The method of claim 22, wherein theacoustic source transmits the predetermined acoustic signals at multiplelocations along the optical waveguide.
 25. The method of claim 24,wherein the acoustic source transmits the predetermined acoustic signalsat different amplitudes at each of the multiple locations.
 26. Themethod of claim 24, wherein the acoustic source transmits thepredetermined acoustic signals in synchrony with an interrogator. 27.The method of claim 26, wherein the calibrating further comprisesmeasuring a phase of the acoustic signals along the optical waveguide.28. The method of claim 21, wherein the receiving further comprisesdetermining a power of the acoustic signals as received along theoptical waveguide.
 29. The method of claim 21, wherein the receivingfurther comprises determining a power spectral density of the acousticsignals as received along the optical waveguide.
 30. The method of claim21, wherein the receiving further comprises determining an extent of theacoustic signals as received along the optical waveguide.
 31. The methodof claim 21, wherein the calibrating further comprises measuring anacoustic sensitivity along the optical waveguide.
 32. The method ofclaim 21, further comprising transmitting the acoustic signals fromanother well.
 33. The method of claim 21, further comprisingtransmitting the acoustic signals from at or near the earth's surface.34. The method of claim 21, further comprising transmitting Stoneleywaves from at or near a wellhead.
 35. The method of claim 21, furthercomprising transmitting Stoneley waves from a downhole location.
 36. Themethod of claim 21, wherein the receiving further comprises receivingthe acoustic signals by a three-axis reference sensor positionedproximate the optical waveguide.
 37. The method of claim 36, wherein thecalibrating further comprises calibrating the optical distributedacoustic sensing system based on the predetermined acoustic signals asdetected by the three-axis reference sensor.
 38. The method of claim 36,wherein the three-axis reference sensor comprises a geophone.
 39. Themethod of claim 21, wherein the calibrating further comprises computingan acoustic point spread function along the optical waveguide for eachof multiple source locations.
 40. The method of claim 39, wherein thecalibrating further comprises using the point spread function determinedby the computing to deblur acoustic emissions along a wellbore asreceived by the optical waveguide.
 41. A method of calibrating anoptical distributed acoustic sensing system, the method comprising:displacing at least one acoustic source along an optical waveguidepositioned proximate a well; transmitting predetermined acoustic signalsfrom the acoustic source; receiving the predetermined acoustic signalswith the optical waveguide; and calibrating the optical distributedacoustic sensing system based on the received predetermined acousticsignals.
 42. The method of claim 41, wherein the displacing furthercomprises displacing the acoustic source through a wellbore.
 43. Themethod of claim 41, wherein the acoustic source transmits thepredetermined acoustic signals at multiple locations along the opticalwaveguide.
 44. The method of claim 43, wherein the acoustic sourcetransmits the predetermined acoustic signals at different volumes ateach of the multiple locations.
 45. The method of claim 43, wherein theacoustic source transmits the predetermined acoustic signals insynchrony with an interrogator.
 46. The method of claim 45, wherein thecalibrating further comprises measuring a phase of the acoustic signalsalong the optical waveguide.
 47. The method of claim 41, wherein thereceiving further comprises determining a power of the acoustic signalsas received along the optical waveguide.
 48. The method of claim 41,wherein the receiving further comprises determining a power spectraldensity of the acoustic signals as received along the optical waveguide.49. The method of claim 41, wherein the receiving further comprisesdetermining an extent of the acoustic signals as received along theoptical waveguide.
 50. The method of claim 41, wherein the calibratingfurther comprises measuring an acoustic sensitivity along the opticalwaveguide.
 51. The method of claim 41, wherein the transmitting furthercomprises transmitting the acoustic signals from another well.
 52. Themethod of claim 41, wherein the transmitting further comprisestransmitting the acoustic signals from at or near the earth's surface.53. The method of claim 41, wherein the transmitting further comprisestransmitting Stoneley waves from at or near a wellhead.
 54. The methodof claim 41, wherein the transmitting further comprises transmittingStoneley waves from a downhole location.
 55. The method of claim 41,wherein the receiving further comprises receiving the acoustic signalsby a three-axis reference sensor positioned proximate the opticalwaveguide.
 56. The method of claim 55, wherein the calibrating furthercomprises calibrating the optical distributed acoustic sensing systembased on the predetermined acoustic signals as detected by thethree-axis reference sensor.
 57. The method of claim 55, wherein thethree-axis reference sensor comprises a geophone.
 58. The method ofclaim 41, wherein the calibrating further comprises computing anacoustic point spread function along the acoustic waveguide for each ofmultiple source locations.
 59. The method of claim 58, wherein thecalibrating further comprises using the point spread function determinedby the computing to deblur acoustic emissions along a wellbore asreceived by the optical waveguide.
 60. A well system, comprising: anoptical distributed acoustic sensing system including an opticalwaveguide installed in a well, and a backscattered light detection andanalysis device; and at least one acoustic source which transmitspredetermined acoustic signals at multiple spaced apart locations alongthe optical waveguide, wherein the backscattered light detection andanalysis device compensates an output of the optical distributedacoustic sensing system based on the predetermined acoustic signals asreceived at the spaced apart locations along the optical waveguide. 61.The system of claim 60, wherein the acoustic source is displacedadjacent the optical waveguide.
 62. The system of claim 60, wherein theacoustic source is displaced through a wellbore.
 63. The system of claim60, wherein the backscattered light detection and analysis devicedetermines a power of the predetermined acoustic signals as receivedalong the optical waveguide.
 64. The system of claim 60, wherein theacoustic source transmits the predetermined acoustic signals atdifferent volumes at each of the multiple locations.
 65. The system ofclaim 60, wherein the acoustic source transmits the predeterminedacoustic signals in synchrony with an interrogator.
 66. The system ofclaim 65, wherein the backscattered light detection and analysis devicemeasures a phase of the acoustic signals along the optical waveguide.67. The system of claim 60, wherein the backscattered light detectionand analysis device determines a power spectral density of the acousticsignals as received along the optical waveguide.
 68. The system of claim60, wherein the backscattered light detection and analysis devicedetermines an extent of the acoustic signals as received along theoptical waveguide.
 69. The system of claim 60, wherein the backscatteredlight detection and analysis device measures an acoustic sensitivityalong the optical waveguide.
 70. The system of claim 60, wherein theacoustic signals comprise Stoneley waves.
 71. The system of claim 60,wherein the acoustic signals are received by a three-axis referencesensor positioned proximate the optical waveguide.
 72. The system ofclaim 71, wherein the backscattered light detection and analysis devicecompensates the output of the optical distributed acoustic sensingsystem based on the predetermined acoustic signals as detected by thethree-axis reference sensor.
 73. The system of claim 71, wherein thethree-axis reference sensor comprises a geophone.
 74. A method ofcalibrating a distributed acoustic sensing system, the methodcomprising: receiving predetermined acoustic signals along multipleacoustic sensors distributed proximate a well; and computing an acousticpoint spread function along the sensors for each of multiple sourcelocations.
 75. The method of claim 74, further comprising, using thepoint spread function determined by the computing to deblur acousticemissions along a wellbore as received by the distributed acousticsensors.